The embodiments herein relate generally to subterranean formation operations and, more particularly, to breaker coated particulates.
Subterranean formation operations often involve drilling a wellbore in a subterranean formation with a drilling fluid and thereafter optionally placing a cement sheath between the formation and a casing (or liner string) in the wellbore. The cement sheath is formed by pumping a cement slurry through the bottom of the casing and out through an annulus between the outer casing wall and the formation face of the wellbore. The cement slurry then cures in the annular space, thereby forming a sheath of hardened cement that, inter alia, supports and positions the casing in the wellbore and bonds the exterior surface of the casing to the subterranean formation.
After a wellbore has been drilled and optionally a cement sheath formed therein, the subterranean wellbore may be stimulated by hydraulic fracturing treatments. In hydraulic fracturing treatments, a treatment fluid is pumped into a portion of a subterranean formation at a rate and pressure such that the subterranean formation breaks down and one or more fractures are formed. Typically, particulate solids are then deposited in the fractures. These particulate solids, or “proppant particulates” or “proppant,” serve to prevent the fractures from fully closing once the hydraulic pressure is removed by forming a proppant pack. As used herein, the term “proppant pack” refers to a collection of proppant particulates in a fracture. By keeping the fracture from fully closing, the proppant particulates aid in forming conductive paths through which fluids may flow.
Hydraulic fracturing treatments may also be combined with sand control treatments, such as a gravel packing treatment. Such treatments may be referred to as “frac-packing” treatments. In a typical frac-packing treatment, a viscous treatment fluid comprising a plurality of particulates is pumped through an annulus between a wellbore tubular mounted with a screen and the wellbore in a subterranean formation. The fluid may be pumped into perforations through a casing, or directly into the wellbore in the case of open hole completions at a rate and pressure sufficient to create or enhance at least one fracture, and the particulates are deposited in the fracture and in the annulus between the screen and the wellbore. The particulates form a “gravel pack,” and aid in propping open the fracture, as well as controlling the migration of formation fines or other loose particles in the formation from being produced with produced fluids. As used herein, unless specified otherwise, the term “particulate pack” will be used to refer to both proppant packs and gravel packs.
The drilling fluid and treatment fluids used to fracture the subterranean formation and/or place proppant or gravel particulates therein (collectively referred to as “treatment fluids”) are typically viscosified. Viscosified treatment fluids generally have a viscosity that is sufficiently high, for example, to prevent undesired leak-off of fluids into a subterranean formation, to transfer hydraulic pressure, to suspend a variety of particulates for a desired period of time (e.g., proppant particulates), and the like. Generally, such viscosified treatment fluids comprise a gelling agent that may be crosslinked with crosslinking agents to achieve the desired viscosity.
The amount of gelling agent required to adequately viscosify a treatment fluid may be rather large, particularly given that gelling agents may degrade under the high temperature and high pressure environments often found in subterranean formations. Accordingly, additional amounts of the gelling agent may be required to compensate for such degradation, leading to increased cost associated with subterranean formation operations requiring use of the viscosified treatment fluids. Additionally, high amounts of gelling agent may generate increased “residue” in a subterranean formation or on a particulate, such as those forming a particulate pack, where the gelling agent remains attached thereto, causing, for example, a reduction in conductivity of fractures in the formation, thereby lowering the hydrocarbon production. Moreover, the high amounts of gelling agent required for forming adequate viscosified treatment fluids may further lead to increased costs associated with increased loading of crosslinking agents necessary to crosslink the gelling agents and breakers necessary to reduce the viscosity of the viscosified treatment fluid after an operation is complete so that it can be removed from the subterranean formation.